FERC on Thursday deferred making a decision on PJM’s proposal in response to a 2021 order directing the RTO to show cause as to why its rules regarding parameter-limited offers are just and reasonable (EL21-78).
The docket was on the agenda for the commission’s monthly open meeting, but was struck.
FERC had found that PJM’s tariff does not require that offers be selected to arrive at the lowest total costs based on parameter-limited offers, but instead requires that resources be committed based on the lowest-cost offers. It also found that the RTO’s governing documents did not appear to define what should happen if a generator fails to operate according to the parameters in its selected offer. (See FERC Issues Show-cause Order on PJM Parameter-limited Offers.)
“PJM is disappointed that FERC did not act on this show-cause order today,” RTO spokesperson Jeffrey Shields said. “PJM will continue, in the meantime, to work with generation owners to ensure that unit operating parameters are being updated in an effective manner to inform PJM Dispatch of generator availability, particularly during periods of cold temperatures during the upcoming winter.”
The RTO and its stakeholders have been eagerly awaiting a decision. On the day before the commission’s meeting, the PJM Markets and Reliability Committee opted to delay a vote on two competing proposals to define how offers will be selected under the multi-schedule modeling functionality the RTO is planning to add to its market clearing engine. PJM and its Independent Market Monitor had filed a joint motion for expedited action on Sept. 11, urging the commission to “issue an order as soon as practicable.”
Shields said it’s still expected that the MRC will move forward with a vote in December.
“PJM stakeholders voted to postpone the vote by one month, so a stakeholder vote is still scheduled to take place in December. While a FERC order in EL21-78 would have been informative, it is not necessary for stakeholders to proceed with a vote,” he said.
During the Electric Gas Coordination Senior Task Force meeting Nov. 14, Paul Sotkiewicz, president of E-Cubed Policy Associates, said real-time values — which the Monitor and PJM proposed to replace with temporary exceptions in response to the commission’s show-cause order — could be the “linchpin” of addressing the incongruities between the gas and electric markets.
The joint proposal would remove the deadline for submitting temporary exceptions by the close of the day-ahead market to allow them to be used in the real-time market as well.
“The simple solution is to … permit real-time submissions for temporary exceptions,” the Monitor wrote. “This would let resources communicate to PJM their changed operational capability without delay, while maintaining the tariff requirements and standard for review that protect against withholding.”
Monitor Joe Bowring told RTO Insider that real-time values would create a pathway for market sellers to notify and explain to PJM that they are unable to operate according to the schedule that they were dispatched and seek an exception from energy market penalties for not being able to do so. He said a similar capability already exists in the day-ahead market, but if a resource is affected by an issue affecting their performance in real time, no corresponding structure exists.
“What we were asking for is to expand the existing process into the real-time [market],” Bowring said.
The real-time values proposal would not interact with the capacity market and would not provide an exception from Capacity Performance penalties during a performance assessment interval, Bowring said.
The Treasury Department on Nov. 17 released guidelines for the Inflation Reduction Act’s (IRA) investment tax credits (ITC) for clean energy projects, allowing developers to claim the credits for equipment used to connect a solar or wind project to the grid, as well as for standalone energy storage projects.
Under the IRA, both homeowners and commercial clean energy developers can qualify for a 30% ITC through 2032 or possibly 2033.
The department’s notice of proposed rulemaking (NOPR) specifically permits developers to claim the credit for equipment that is a “functionally interdependent” component of a system that generates clean energy, including inverters, converters, and wires and cables up to and including a transformer in a substation.
The 127-page NOPR defines system components as functionally interdependent “if the placing in service of each component is dependent upon the placing in service of each of the other components in order to generate or to store electricity, thermal energy or hydrogen.”
Examples in the proposed rule detail how interconnection equipment in a solar project or offshore wind project could be functionally interdependent and therefore included in the overall project costs for calculation of the ITC once a project has gone online.
The guidelines also provide a broad definition of the kinds of projects ― beyond solar and wind ― that will qualify for the ITC, including geothermal, hydrogen fuel cells, combined heat and power, and bioenergy.
The ITC for standalone storage is another major component of the new guidelines; it covers all technologies and chemistries ― lithium ion, vanadium flow and hydrogen ― as well as thermal energy storage technologies, such as geothermal heat pumps.
Prior to the IRA, the ITC could be claimed only for storage that was directly connected to and charged from a clean energy — solar or wind — project. Electric vehicle batteries and thermal storage used for heating swimming pools are not eligible for the credit.
At the same time, the guidelines include sections noting the proposed definitions of clean generation and storage may need to change as new technologies emerge.
The goal of these and other proposed rules in the guidelines is to provide “companies with clarity and certainty needed to secure financing and advance clean energy projects nationwide,” Deputy Secretary of the Treasury Wally Adeyemo said in a department press release.
The publication of the NOPR in the Federal Register, scheduled for Nov. 22, will begin a 60-day comment period, with a public hearing scheduled for Feb. 20, 2024.
Echoing Adeyemo, solar and renewable energy trade groups stressed the industry’s need for clear and stable tax incentives and, while welcoming the proposed guidelines, cautioned that further details may need to be hammered out for developers to take full advantage of the IRA’s incentives and increase renewable energy generation in the U.S.
“We remain impressed by the administration’s commitment to fully maximizing the economic and environmental benefits of [the IRA], and plan to continue working closely with Treasury in support of fair, timely and practicable final rules across all facets of the clean energy tax package,” said Gregory Wetstone, CEO of the American Council on Renewable Energy.
Abigail Ross Hopper, CEO of the Solar Energy Industries Association, hailed the inclusion of standalone storage in the ITC as a big win for the industry. The proposed guidelines are “good news for America’s clean energy economy. However, given the economic headwinds that many solar and storage companies are facing, we are continuing to fully evaluate the details in this guidance to guard against any potential unintended consequences that might undermine our ability to rapidly deploy clean energy projects of all sizes.”
A Developer’s View
When first passed, the ITC provisions of the IRA were seen as a potential bonanza for the solar industry, reinstating the full 30% ITC for a decade, as opposed to the gradual phaseout passed in the Energy Act of 2020. By August 2022, when President Biden signed the IRA into law, the ITC had been reduced to 26%,
The law also allows nonprofits, schools, and city and local governments ― which previously could not benefit from the ITC ― to receive a direct payment of the credits or transfer of them to third parties. Other provisions offer additional credits of 10% each for projects meeting domestic content requirements or located in low-income or “energy” communities ― areas that have lost jobs and tax revenues due to the closing of fossil fuel plants.
But the tax credits for commercial projects also come with requirements that developers pay prevailing wages and bring in registered apprenticeship programs. Any projects not meeting those requirements would be eligible for only a 6% ITC.
In addition, the prevailing wage and apprenticeship requirements apply to any workers employed for the operation, maintenance or repair of a project for a period of five years from the date it goes online.
The IRA has driven expansion in the clean energy sector, especially in domestic supply chains. Solar and storage companies have announced $100 billion in new investments across the U.S. since the law was passed, according to Hopper.
But while growing, the industry continues to be plagued by supply chain, interconnection and other delays. According to a recent report from the American Clean Power Association, more than 16 GW of clean energy projects have been delayed this year, about two-thirds of them solar.
The complexity and slow rollout of tax credit guidance from the Treasury Department — coupled with inflation and delays — have meant uncertainty for some developers as investors continue to wait on the sidelines.
In an interview with NetZero Insider, Mike Healy, CEO of New Columbia Solar, a residential and commercial installer based in Washington, D.C., said a major drawback of the ITC as structured is that it’s not available to developers or homeowners until a project comes online.
“When you’re developing a solar project, you’re underwriting the economics way before you get to interconnection,” said Healy, who also is president of the board of the Chesapeake Solar and Storage Association (CHESSA), the regional trade group for D.C., Maryland and Virginia.
“Yet, with the IRA, you can only submit at interconnection, and then you get told afterwards [if a project qualifies], so it’s not a great process,” he said, noting that his personal views are not CHESSA’s.
The IRA and ITC will be “transformative,” Healy said, but solar’s long development cycle and uncertainty about tax credits can result in fewer benefits for customers. Nailing down the ITC “as early as possible in the development cycle is the only real way to underwrite it to make sure that all parties involved in the solar process get the benefit,” he said.
New Mexico regulators on Nov. 16 adopted zero-emission requirements for cars and trucks, a move that proponents say will improve air quality, fight climate change and increase consumers’ choice of vehicles.
The state Environmental Improvement Board (EIB) voted to adopt California’s Advanced Clean Cars II rules — but with a twist. In California, ACC II will increase manufacturers’ supply of zero-emission cars each year through 2035, when the sale of gas-powered cars will be banned with the exception of a limited number of plug-in hybrids. (See California Adopts Rule Banning Gas-powered Car Sales in 2035.)
In contrast, New Mexico has opted to follow ACC II through 2032, when 82% of cars that manufacturers deliver for sale must be zero-emission. Colorado took a similar approach: The state’s Air Quality Control Commission last month adopted ACC II with a maximum ZEV requirement of 82% in 2032.
Clean Cars, Trucks
In New Mexico, the EIB also voted Nov. 16 to adopt California’s Advanced Clean Trucks (ACT), a rule that requires an increasing percentage of medium- and heavy-duty trucks sold in the state to be zero-emission. ACC II and ACT in New Mexico will begin with vehicle model year 2027.
The rules package also includes more stringent emission standards for internal combustion vehicles. The package was adopted during a joint hearing of the EIB and the Albuquerque-Bernalillo County Air Quality Control Board, which governs air quality within Bernalillo County.
Following the board votes, the New Mexico Environment Department (NMED) said the rules package “will significantly increase consumer choice for New Mexicans by assuring new and used zero-emission vehicles are available for lease or purchase.”
The rules also reflect New Mexico Gov. Michelle Lujan Grisham’s commitment to a “cleaner, greener future,” NMED said. Lujan Grisham (D) announced in July that the state would enact the clean cars and trucks rules.
Adoption of the rules was welcomed by a coalition of climate, environmental justice and business groups known as New Mexico Clean Air.
“New Mexicans will be able to breathe easier, buy more clean, affordable vehicles and help put the brakes on climate change with the adoption of Clean Cars and Trucks Standards,” Alexis Mena, New Mexico policy director at the Natural Resources Defense Council, said in a statement.
Opponents said the California rules are a poor fit for New Mexico.
Nicholas Maxwell, a resident of rural Lea County, said New Mexico’s path must account for “the vast rural spaces and the spirit of independence that define us.”
“The economic impact of these proposed standards shouldn’t be underestimated,” Maxwell told the EIB. “We should avoid speeding toward a future that our current infrastructure and economy are not ready to support.”
Keeping Up with California
The federal Clean Air Act allows California to adopt its own vehicle emission standards if they are at least as stringent as the federal standards. The state must receive an EPA waiver before it can enforce its own emission rules.
Other states may adopt California’s rules or stick with the federal emission standards.
New Mexico adopted ACC II’s predecessor, Advanced Clean Cars, in May 2022. (SeeNM Adopts Calif. Advanced Clean Cars Rules.) Just a few months later, in August 2022, California updated its rules with the adoption of ACC II.
As a result, New Mexico no longer will be able to enforce the first version of Advanced Clean Cars after California receives an EPA waiver for ACC II, according to Claudia Borchert, NMED’s climate change bureau chief.
“Without these amendments, these rules as they exist today will be unenforceable — once EPA as anticipated grants a waiver for ACC II,” Borchert said during the EIB hearing.
Under ACC II, automakers face a steep jump to deliver 43% ZEVs for sale in model year 2027.
But Borchert said manufacturers have a number of ways to earn credits and reduce the actual number of ZEVs they must deliver in a particular year.
They may apply early action credits earned from ZEVs supplied before model year 2027. Up to 20% of the ZEV requirement may be met with plug-in hybrid electric vehicles (PHEVs). Credits may be bought or sold from other automakers or banked for later.
And manufacturers may help fill a deficit in one state with credits from oversupplying ZEVs in another ACC II state.
In addition, extra credits may be earned by selling previously leased ZEVs through a financial assistance program, providing new ZEVs at a discount to community-based clean mobility programs or delivering less expensive new ZEVs or PHEVs. For the latter, the extra credit is available for zero-emission cars with a manufacturer’s suggested retail price of $20,250 or less and light trucks with an MSRP of $26,670 or less.
If manufacturers take full advantage of the various credits, the minimum ZEV delivery requirements drop to as low as 8% in model year 2027, Borchert said in written testimony.
“That 8% target for the first model year of compliance is not much greater than New Mexico’s projected 2023 market share of BEVs of 4.5%,” Borchert said.
ALBANY, N.Y. — New York on Thursday significantly increased its commitment to its electric vehicle charging infrastructure, boosting the EV Make-Ready Program’s budget from $701 million to $1.24 billion (18-E-0138).
At its Nov. 16 meeting, the New York Public Service Commission (PSC) endorsed the recommendations of the Department of Public Service’s (DPS) Make-Ready midpoint review whitepaper, which called for new programs and changing the mix of Level 2 and DC Fast Chargers (DCFC).
Launched in 2020, the Make-Ready program subsidizes 50% to 100% of costs to make a site ready for EV charging, including equipment on the utility and customer sides of the meter. It is overseen by the DPS but primarily executed by six of New York’s utilities.
As of the midpoint review, the six investor-owned utilities have committed or completed 12,475 L2 chargers (23% of the original goal of 53,770) and 630 of the planned 1,500 DC Fast Chargers (42%).
DPS acknowledged the state’s EV growth has not kept pace with the goals of the Climate Leadership and Community Protection Act (CLCPA). The state currently has about 175,000 electric or plug-in hybrids, far below the CLCPA’s goal of 850,000 by 2025.
The PSC order reflects higher costs — increasing L2 chargers by up to 37% and nearly doubling estimates for DCFC. It also changes the mix of chargers
The PSC had assumed that 57% of New York City residents and 82% of those outside the city have some access to residential charging. The commission’s new forecast assumes that early adopters — those purchasing EVs through 2025 — will have greater access to residential charging options than the population at large, with 77% of early adopters in New York City and 95% those outside have access to residential charging.
As a result of the new data, the PSC changed the target for EV plug installations to 38,356 Level 2 (L2) plugs (down from 53,773) and 6,302 direct current fast charger (DCFC) plugs (up from 1,500).
The modified Make-Ready program also seeks to address infrastructure gaps and improve accessibility to disadvantaged communities (DACs). The PSC’s order:
Allocates an extra $166 million for EV deployment in disadvantaged communities, taking the total to $327 million;
Increases the budget for the medium- and heavy-duty (MHD) Make-Ready pilot to $67 million;
Creates a $25 million program focusing on DACs to provide micromobility charging — lightweight, low-speed devices, such as electric bikes and electric scooters; and
Extends the Make-Ready program’s deadline beyond Jan. 1, 2025, if the plug targets remain unmet.
The commission also created a stakeholder-led process to address issues related to EV charging projects stuck in interconnection queues and directed Consolidated Edison to increase the allowable output per charging site to 6 MW,
The PSC’s order also directed the utilities to standardize data collection and reporting, to ensure curbside chargers are limited to EV charging-only parking spaces and to display contact information for EV servicing at all program-funded charging sites.
The budget increase is expected to increase ratepayer bills by 0.7% to 1.7%, depending on the utility. The expanded investment should stimulate an additional $4 billion in EV and infrastructure investments, Gov. Kathy Hochul (D) said in a press release.
EV Make-Ready program eligible costs | Joint Utilities of New York
PSC Questions & Comments
Before voting to expand the Make-Ready program, the commissioners raised questions about accessibility, micromobility and infrastructure.
Commissioner Diane Burman voiced concerns about the whitepaper’s recommendation for a subgroup focusing on the interconnection queue.
Zeryai Hagos, DPS’s deputy director of the Office of Markets and Innovation, explained the new EV Infrastructure Interconnection Working Group (EVIIWG) would investigate new processes that might help EV charging projects get through interconnection queues more quickly. The staff whitepaper said the working group would be similar to two initiatives that helped eliminate a backlog of distributed energy resource (DER) applications in interconnection queues.
Burman next inquired about the directive calling on Con Edison, which is installing about one third of the EV chargers statewide, to submit a proposal to streamline its queue management for EVs and why it was chosen for this task versus other utilities.
Hagos replied that ConEd’s experience in New York City could offer a statewide model for EV improvements and deployment. Burman accepted this argument but commented, “one size doesn’t fit all.”
Burman sought assurances that PSC funding would both address traffic and safety concerns raised around micromobility vehicles and that any funding would be directed to the DACs where these smaller E-bikes or scooters are most often used.
Jen Roberton, transportation lead at DPS, acknowledged traffic safety issues and fire concerns over micromobility vehicles, while highlighting the program’s focus on providing charging infrastructure in DACs, particularly for the 60,000 plus food delivery workforce operating E-bikes and scooters in New York City.
Burman also questioned the program’s limitations on energy storage devices paired with EVs, saying “we may be missing the mark” by preventing them from being used for backup power.
Roberton acknowledged potential lost opportunities but said the PSC was attempting to avoid “double incentivizing” storage.
“We have other programs that support storage [and] we don’t want to have site hosts … access some of our storage-related incentives administered by utilities and then also get an incentive to make-ready,” Roberton said. “So the intent was to make sure that the incentives were going to the right place.”
Commissioner John Howard asked about New York’s progress toward its EV adoption goals and if staff thought the state was on track to achieve its CLCPA goal of having 850,000 EVs by 2025.
Hagos said the state will not meet the 2025 goal, saying supply chain disruptions during the COVID-19 pandemic and domestic content rules in the Inflation Reduction Act slowed EV adoption. But he said the state could reach its 850,000 target by 2026 or 2027.
Howard also expressed concern about the reliability of EV chargers, saying as many as one in four of New York’s fleet do not work on a given day.
Roberton concurred this is a considerable barrier to EV adoption. DPS is adopting national reliability standards to improve its data collection.
On micromobility, Howard urged more direct engagement with fire stations to address concerns about battery explosions and fires involving E-bikes and scooters. Roberton confirmed the DPS has ongoing discussions with fire departments over micromobility safety.
Other commissioners placed the PSC’s approval and status of the Make-Ready program into the wider perspective.
“This is very ambitious, and at some point, I think ambition and reality will come face-to-face,” said Commissioner James Alesi. “I hope that ambition prevails.”
Commissioner John Maggiore highlighted the roadblocks confronting New York as it transitions its fleet of vehicles to EVs, but expressed optimism, saying “we are going to encounter other difficulties, but it’s a noble goal, and I think we are going to achieve the goal.”
Reaction
Environmental groups, EV operating and charging infrastructure companies, and community leaders, were equally optimistic, welcoming the PSC’s decision to approve the midpoint review and order more investment into the Make-Ready program.
Jason Zarillo, president of Livingston Energy Group, an EV infrastructure installation and management company, said the order will drive more EV investment and create jobs as well as enable consumers to “feel confident in purchasing EVs.”
Frank Reig, CEO of Revel, which runs an electric moped sharing service in New York City, said, “the door to EVs in New York” has been opened. He said his company is committed to “bringing the largest network of public fast charging infrastructure to the communities that will benefit most from zero emission EVs.”
Caroline Samponaro, VP of micromobility policy at ride-sharing company Lyft, also hailed the continued EV investment, saying it, “will help break down the primary barriers to widespread EV adoption.”
Pamela MacDougall, director of grid modernization strategy at the Environmental Defense Fund, commended the PSC for “continuing to prioritize vehicle charging and significantly expanding accessibility of funds to disadvantaged communities.”
The Chesapeake Climate Action Network (CCAN) Action Fund on Thursday released a report arguing that Dominion Energy can meet growing demand for electricity in its territory with clean energy instead of building new natural gas plants, as it has proposed.
The report, which the environmental group commissioned from the consultancy Gabel Associates, pushes back against Dominion’s pending integrated resource plan that was filed with the Virginia State Corporation Commission this spring. (See Enviros Pan Dominion Integrated Resource Plan.)
“Unfortunately, Dominion’s plan is not compliant with laws passed by the General Assembly in 2020 and 2021, including the Virginia Clean Economy Act and regulatory directives to account for economic externalities associated with air pollution,” the report said. “As an example, Dominion intends to build 1,000 MW of new gas-fired generation capacity in Chesterfield County by 2027 even though doing so will generate more than 2 million tons of additional carbon emissions each year.”
The utility expects peak demand to grow by 2.32% and overall energy consumption by 3.25% annually, which the report said could be met while retiring coal- and gas-fired power plants using PJM’s generator replacement process to avoid queue delays, adding battery storage at existing sites, expanding behind-the-meter solar and increasing energy efficiency and demand response.
“Dominion has a chance to cut costs for Virginians by $28 billion and slash greenhouse gas emissions by 52 million tons over the next decade without compromising system reliability simply by switching out old fossil fuel plants for new solar panels and battery systems,” Gabel Associates Vice President Adrian Kimbrough said.
Dominion’s load growth projections are based on assumptions including significant growth in data centers in its territory, though the report said it is unclear if this growth is made up of projections or actual contractual arrangements. The projections also include efficiency and demand-side management, but the report questions whether those could be higher and lead to lower load growth.
The IRP has already seen proceedings in the SCC; in a brief filed in late October, Dominion said it had picked a middle path of data center growth out of three scenarios, which was reviewed by PJM, as the commission has required in the past. The first five years of that forecast are more certain than the later 10 covered in the IRP, the utility said.
CCAN and Gabel proposed an alternate resource plan, which would hold constant the current and contracted renewables Dominion has while accelerating the retirement of 8.5 GW of fossil fuel capacity that has operated for 20 years. The retired capacity would be replaced with a range of solar, including the company’s own utility-scale projects, behind-the-meter resources and contracts with third-party developers. Dominion would also need to add battery storage to sites of existing and planned renewable energy generators using PJM’s Surplus Interconnection Queue.
The report does not get into specifics for what should replace the retiring capacity and avoided new fossil plants because it is meant to provide a high-level alternative to Dominion’s proposals.
CCAN said the report bolsters the argument that a proposed 1,000-MW natural gas plant in Chesterfield is not needed. The group and some local citizens are opposing the plant’s construction.
Dominion told the SCC last month that dual-fuel combustion turbines like the one proposed for Chesterfield are “currently the most cost-effective and reliable resource” to meet a future long-duration winter event or capacity shortage. Other parties including Advanced Energy United and the Sierra Club have pushed back on its plans for new gas plants.
“Reliability is paramount to the company, and the significant increase in the load forecast, coupled with events like Winter Storm Elliott, have highlighted the need for dispatchable generation and the reliability benefits of natural gas units” to serve the company’s customers, Dominion said in its filing.
Dominion said the IRP is not the proper venue to litigate the need for specific power plants, as the SCC does not approve or reject any actual plants in such proceedings. The firm will have to apply for a certificate of need and public necessity for specific plants, which is where the need for actual powers is properly debated, it said.
LA QUINTA, Calif. — As pressure grows to decarbonize the electricity sector, grid operators increasingly are grappling with how to coordinate the retirement of traditional resources with the introduction of new non-emitting resources — all while ensuring reliability and affordability.
Challenges of the grid’s transition was a running theme of the discussions among utility regulators and power industry stakeholders at the National Association of Regulatory Utility Commissioners’ Annual Meeting in the Southern California desert Nov. 12 -15.
“In these discussions you get the question of what keeps you up at night,” MISO CEO John Bear said. “The transition … is probably the biggest concern that we have.”
In a Nov. 14 panel, RTO/ISO executives identified the litany of challenges their organizations face as they attempt to retire thermal generation and integrate renewables onto the grid.
“We have to keep the lights on and keep the power affordable through the transition,” PJM CEO Manu Asthana said. “The big difference is the new resources that are coming on are not predictable in the same way that the old resources were.”
With the retirement of thermal generation comes the challenge of ensuring there are enough dependable resources to fill the gap when weather-dependent renewables can’t serve load. The introduction of new technologies has been slow, and if traditional resources are retired too soon, grid operators fear the worst.
“That’s probably one of my biggest concerns, is that we will let these resources that we have, that we use today, retire and not have the replacement resources come in time,” Asthana said. “We just can’t let that happen.”
Asthana pointed out that PJM is on track to retire about 40 GW of resources by 2030; Calpine’s Joseph Kerecman told RTO Insider that may be an understatement. (See PJM Whitepaper to Highlight Future RA Concerns.)
The solution, the CEOs said, is to keep some traditional methods of generation, like natural gas plants, on the grid as long as possible in combination with renewables to ensure reliability.
“There’s a lot of pressure to not build gas infrastructure, but gas is the marginal fuel in our markets,” Asthana said. “We’re approaching this intersection where we know we have to decarbonize the system, but I think we are at risk of not doing so in an orderly fashion.”
NERC CEO Jim Robb emphasized another solution to make a smoother transition: getting better standards in place for inverter-based resources. He noted that while inverter-based resources are currently “grid-following,” they will have to form the grid when they start making up 40 to 60% of the generation mix.
“That’s the path toward a carbon-free grid: having grid-forming technology through power electronics. But we’re not there yet,” he said.
Greater Gas-electric Coordination Needed
Robb said the electric industry is the largest consumer of natural gas, and with the increasing demand for electrification comes a greater need for coordination between the electric and gas sectors.
“If we continue to just build out the electric sector, but we’re not paying attention to the fuel infrastructure behind it, we’re going to run into a lot of issues,” Robb said.
During a Nov. 15 panel, commissioners, regulators and strategists emphasized the need to view and operate the grid as a single entity.
“There’s two separate grids right now,” said Jason Ketchum, vice president at ONE Gas, a Oklahoma-based utility that also serves customers in Texas and Kansas. “There’s a gas grid, and there’s an electric grid, and we need to start talking about the energy grid.”
Diverting from many of the week’s climate-focused conversations, Ketchum emphasized the importance of listening to the customer and recognizing that people in some communities may not have the interest or capability to moderate their lifestyles in the interest of burning less gas.
“We serve a pretty wide geographic area, and a lot of our communities are different,” Ketchum said. “Some are more focused on environmental issues; others are more focused on affordability.”
Georgia Public Service Commissioner Tricia Pridemore, who moderated the panel, asked “if the answer to all of this” was to build more pipelines.
Not necessarily, Ketchum said: Focus on delivering whatever the best asset is to the customer in any given area. But he also emphasized gas as an important economic driver.
“There’s a lot of parts of our region that don’t have gas that can’t grow economically,” he said. “It’s a great opportunity to locate assets in areas that can really help out those communities.”
Getting into GEAR
North Dakota Public Service Commissioner Julie Fedorchak, who was elected NARUC president during the conference, announced a new initiative called Gas-Electric Alignment for Reliability (GEAR).
Led by Pridemore, NARUC’s newly elected vice president, GEAR will bring together a task force of regulators, utilities, grid and pipeline operators, and gas producers and suppliers to help better coordinate the gas and electric industries. Energy officials are hopeful GEAR will initiate meaningful progress toward greater gas-electric coordination to meet the country’s reliability and clean energy needs.
“This is going to be a messy transition, almost guaranteed,” PJM’s Asthana said. “But I’m almost certain we’re going to solve this problem.”
However, the possibility of one or more prolonged cold weather events, along with drought and wildfires continuing through the season, means significant reliability risks remain, NERC staff told commissioners at FERC’s open meeting.
The concern was stated most bluntly by Mark Lauby, NERC’s chief engineer, who spoke after Commissioners Allison Clements and Mark Christie responded to FERC staff’s presentation of the report. Although Clements noted the mild weather forecast and natural gas futures prices as “areas for optimism,” and Christie said “hopefully we’ll get through [winter] with some luck,” Lauby professed to being “taken aback” by the commissioners’ comments.
“I don’t like to plan on hopes and dreams,” Lauby said, noting NERC’s own recently released 2023 Winter Reliability Assessment warned that much of the North American electric grid faces elevated or high risk of energy shortfalls in December, January and February. (See NERC: Grid Risks Widespread in Winter Months.) “And even if, in fact, we have an average winter, that doesn’t mean we won’t have a cold spell during the winter. … That’s the kind of stuff that keeps me up at night.”
Mild Temperatures in North, West
FERC’s assessment cited the National Oceanic and Atmospheric Administration’s seasonal temperature outlook, which predicted that a strong El Niño effect in the Pacific Ocean will bring warm temperatures to the West Coast, leading to a strong likelihood of higher-than-normal temperatures across the northern U.S. The Southern states are equally likely to experience below-average temperatures as they are to experience above-average ones.
The likelihood of higher temperatures during the winter months — particularly in colder regions of the country — suggests less energy will be needed for heating and a lower likelihood of insufficient gas for both heating and electricity, FERC’s report said. But the assessment also noted that NOAA’s forecasts “do not include the probability of extreme cold weather events,” which can affect energy supply and demand in unforeseen ways, and that “below-freezing temperatures can stress critical infrastructure … especially natural gas facilities.”
Drought conditions are also expected to persist in the central U.S. through winter, potentially causing problems for hydropower plants in the north-central U.S. and lack of fresh water for thermal plants in the south-central areas. Similar conditions are predicted for the Pacific Northwest as well. In addition, the Canadian wildfire season — including several large existing fires — is now expected to continue into winter, which could affect regions in the U.S. with connections to Canada such as WECC, MISO and ISO-NE.
Drops Expected in Gas, Electricity Prices
FERC’s report said natural gas prices are expected to be lower this winter than in previous years, despite rising demand, thanks to growing production and high natural gas storage levels. But while market fundamentals “indicate adequate availability of natural gas at the national level,” local fuel availability may still be affected by “regional constraints.”
According to the assessment, the predicted average natural gas demand is expected to reach 122.4 Bcfd, 4% over last winter and 7.2% more than the previous five-year average. Electricity generation constitutes about a quarter of this demand, at 32 Bcfd, with residential and commercial use making up the largest share, at 42.3 Bcfd. The biggest growth in demand is from net natural gas exports, which are projected to average 13 Bcfd this winter, up 21% from winter 2022-2023 and 62% from the previous five-year average.
Gas futures prices Nov. 1 were lower than the final settled futures prices for last year at all of the trading hubs cited in the report, and at several hubs, they were below the previous year’s final settled prices as well. FERC’s report attributed last winter’s soaring prices to the impact of Winter Storm Elliott in late December.
Wholesale electricity prices are also projected to decline at most major pricing hubs compared to last winter, the assessment said, with the greatest difference seen in the West, where last year’s record high gas prices contributed to higher electricity prices as well. Declines of at least $5/MWh are also expected in the Southeast, NYISO and PJM.
In SPP, prices are expected to increase from $37.81 on average last winter to $38.21 this winter. However, SPP is projected to have the lowest wholesale electricity prices on average of any region, the report said.
FERC last week accepted SPP’s proposed tariff revisions for Basin Electric Power Cooperative’s formulate rate template, suspending them for a nominal period, effective Nov. 14, subject to refund, and established hearing and settlement judge procedures.
The commission said in its Nov. 13 order that its preliminary analysis indicated the proposed revisions have not been shown to be just and reasonable and that they raise issues of material fact more appropriately addressed in the hearing and settlement judge procedures (ER23-2836).
FERC did find that a 50-basis point adder it previously granted Basin Electric for RTO participation still was appropriate, given Basin Electric’s continued membership in SPP. It said that the cooperative’s return on equity (ROE), inclusive of the adder, must remain within the zone of reasonableness during the hearing and settlement judge proceedings.
SPP filed the tariff changes in September after FERC said Basin Electric became subject to its jurisdiction when it readmitted Tri-State Generation and Transmission Association as a non-exempt Class A member in November 2019. Basin Electric proposed to revise its template to reflect a base ROE of 9.69% and the 50-basis point adder for its SPP membership and calculated an 8.65%-11.12% composite zone of reasonableness.
The cooperative also proposed to revise its template to reflect a capital structure of 48.22% equity and 51.78% long-term debt, based on the weighted average capital structure of transmission owners across the SPP region. Basin Electric claimed that because it is the largest non-governmental transmission owner by capitalization in SPP’s Upper Missouri pricing zone, it is appropriate to rely on the weighted average capital structure used in all SPP transmission owners’ formula rates.
The proposed ROE and capital structure would result in an increase to the 2022 annual transmission revenue requirement of $4.68 million, Basin Electric said. That is about 4% under its 2022 ATRR under the existing template.
Black Hills Settlement OK’d
FERC on Nov. 16 approved an uncontested settlement of Black Hills Colorado Electric’s proposed tariff revisions to transition from a stated transmission rate to a forward-looking formula rate for transmission service (ER22-2185).
The commission last year accepted and suspended, subject to refund, the utility’s proposed revisions, setting the proceeding for hearing and settlement judge procedures. An administrative law judge approved the settlement with intervenors Tri-State and Arkansas River Power Authority in September and certified the agreement to FERC on Oct. 4.
Commission trial staff supported the settlement, saying its approval “will resolve all issues set for hearing.” They said the agreement provides “significant benefits to ratepayers,” pointing to an ROE of 9.8% that was lower than the filed ROE of 10.44%.
Staff also said a fixed capital structure of 47% equity and 53% debt is “both reasonable and preferrable” to the company’s as-filed proposal for variable capital structure. A three-year moratorium of “key components of the formula rate” avoids further litigation, they said.
CARMEL, Ind. — Weeks after the nearly $2 billion Joint Targeted Interconnection Queue (JTIQ) transmission portfolio was awarded a $465 million Department of Energy grant, MISO and SPP are switching their proposed cost allocation for the projects.
Now, all costs of the JTIQ portfolio should be assigned to interconnection customers, MISO and SPP have agreed. The new cost allocation will replace the RTOs’ previously proposed 90% assignment to interconnecting generators with the remaining 10% to load.
The RTOs have further said all operations and maintenance costs on the projects will be borne by the constructing RTO’s load.
MISO Director of Resource Utilization Andy Witmeier said MISO, SPP and states are in the middle of negotiations with DOE before they can receive the money.
Speaking at a Nov. 15 Planning Advisory Committee meeting, Witmeier said the grant will help get the JTIQ portfolio online “to the benefit of generators waiting to interconnect.” And he said a more simplified cost allocation likely will help move the projects across the finish line, even though MISO and SPP had settled on the 90/10 allocation almost a year ago.
“This is what MISO and SPP believe will have the most success in getting approved,” he said.
Witmeier characterized the change in direction on cost allocation as a “small pivot.” He said MISO always would have used the grant money to apply for the load’s share of project costs first, and the $464 million grant more than takes care of the tab load would have picked up under the original cost allocation proposal.
Witmeier said MISO and SPP concluded DOE’s funding can address rate complexities the 10% allocation to load will introduce in how costs will be spread across load and how operations and maintenance costs will be handled. He said using a 100% allocation ensures entitlements are assigned to the constructing region and reduces risk that load in one RTO is supplementing transmission in the other in the unlikely case not enough generation shows up to fund the lines.
Witmeier said the 100% method is a “much simpler rate design, if you don’t have load in that calculation.”
He also said the 100% allocation to generators matches SPP’s existing interconnection upgrades allocation and allows MISO and SPP to approach FERC with a “consistent approach.”
“The 100% is a small shift for MISO, but the 90/10 was a big shift for SPP,” he said.
In MISO’s individual queue process, interconnection customers bear 100% of interconnection costs except when network upgrades are 345 kV or higher, when the 90% to interconnection customers, 10% to load allocation kicks in.
In an email to RTO Insider, SPP confirmed the new rate design will be a better fit with its current cost allocation for generator interconnection projects.
Xcel Energy’s Carolyn Wetterlin said her utility agrees with the change. She said a 100% allocation will result in a “cleaner filing” to FERC and less costs borne by ratepayers in MISO and SPP.
However, the Coalition of Midwest Power Producers’ Travis Stewart said the change is significant and interconnection customers have concerns.
National Grid Renewables’ Maggie Kristian said some generation developers weren’t comfortable with load’s small share in the allocation to begin with. She said it’s disappointing to see even that small amount reduced to nothing.
Witmeier said the 100% cost allocation to projects will apply only to the first JTIQ portfolio. He said MISO and SPP will have to “go back to the drawing board” for future JTIQ portfolios and devise a new cost allocation. The RTOs hope FERC gives its blessing for JTIQ planning to become a cyclical process and replace their affected system study process.
Witmeier also said there are always lingering concerns about free riders in transmission cost allocation. He said while interconnection customers might be upset to completely cover the JTIQ bill, load is probably unhappy taking on 100% of MISO’s long-range transmission plan costs.
“We’ve been having this discussion in the MISO community for the past 15-20 years, what is the appropriate formula for generation and load,” Witmeier said.
He said while MISO will hear written concerns on the allocation change through Dec. 6, it’s unlikely to influence changes to MISO and SPP’s direction.
The RTOs also found a change in adjusted production cost benefits of the JTIQ portfolio between MISO and SPP since it first conducted a benefits analysis in 2021. Now MISO can expect to see a $76.5 million benefit, while SPP will experience $99.3 million in benefits over 20 years. The RTOs originally found a $55.7 benefit for MISO and a $132.9 benefit for SPP over the first 10 years the projects are in service.
As far as how the DOE grant will be split between MISO and SPP, that’s unknown, Witmeier said. He said that depends on how many projects apiece from the MISO or SPP clear their respective interconnection queues.
ERCOT canceled its effort to procure additional generation capacity this winter Nov. 17, citing “limited response” from the market.
The Texas grid operator was seeking 3,000 MW of capacity with its request for proposal. Participants responded with 11.1 MW of “potentially eligible” capacity.
ERCOT CEO Pablo Vegas said Nov. 17 during an interview that it was “disappointing that there wasn’t more available.”
“One of the important outcomes of this RFP process was learning what the market response would be to this type of capacity request,” he said in a statement. “We’ll take these lessons and continue to work with the [Public Utility Commission of Texas] and the market to evaluate other types of demand response products that could contribute meaningfully to electric reliability in the future.”
The ISO announced its intention in October to increase operating reserves this winter. It listed 20 mothballed and seasonally mothballed dispatchable resources that were eligible to respond to the RFP. Austin Energy and CPS Energy, owners of three of the four largest plants on the list, have said they would not bring their decommissioned units back to life. (See ERCOT Searching for 3 GW of Winter Capacity.)
Talen Energy notified ERCOT in August that it was planning to indefinitely suspend operations at the other large plant on the list, its 292-MW gas unit outside Corpus Christi. The grid operator evaluated offering a reliability-must-run contract for Barney Davis before Talen withdrew the suspension request on Oct. 27. (See “ERCOT Evaluating RMR Options,” Texas Public Utility Commission Briefs: Aug. 24, 2023.)
Vegas said no generators offered their decommissioned units in response to the RFP, which presented three-month contracts that were to begin Dec. 1. The program’s 11.1 MW came from entities offering to shed load during emergency conditions.
The awards would have been announced Thursday.
The ISO said it weighed factors such as the program’s costs and the incremental additional complexity for its control room against the very small amount of capacity and the minimal reliability benefits in declining to proceed with the RFP.
“It will come as a surprise to no one that knows anything about power markets that ERCOT’s Hail Mary attempt to procure zombie power plants failed,” Stoic Energy CEO Doug Lewin said on X, formerly known as Twitter, putting in a plug for energy efficiency’s benefits.
The RFP also drew pushback from the PUC’s commissioners, who expressed concerns during an open meeting earlier this month over ERCOT’s refusal to place a firm cap on the program’s costs. Vegas told the commission staff had not yet set a budget for the RFP.
Commissioner Will McAdams said the RFP should be considered an interim or bridge solution under state rules. That would mean it would compete with funds under the $1 billion cap designated for the performance credit mechanism.
ERCOT said it “firmly believes” expanding demand response capabilities in the industrial, commercial and residential customer classes offers “tremendous potential.” It said it will work with the PUC and stakeholders to explore incentives and product designs that may work better in the future.
The RFP was based on probabilistic analysis indicating ERCOT faced a 20% risk of entering energy emergency alert conditions this winter if the system was hit with another event similar to last December’s Winter Storm Elliott. It said the 3,000 MW of additional capacity that could be called upon if needed was an “added layer of protection” during peak demand.
“The [RFP] was an extra layer of precaution to mitigate higher risk during extreme weather this winter,” Vegas said. “ERCOT is not projecting emergency conditions this winter and expects to have adequate resources to meet demand.”
